An electric power system comprises a power transmission and/or distribution network interconnecting geographically separated regions, and a plurality of substations at the nodes of the power network. The substations include equipment for transforming voltages and for switching connections between individual lines of the power network. Power generation and load flow to consumers is managed by a central Energy Management System (EMS) and/or supervised by a Supervisory Control And Data Acquisition (SCADA) system located at a Network Control Centre (NCC).
Substations in high and medium voltage power networks include primary devices such as electrical cables, lines, bus bars, power transformers, instrument transformers as well as switching devices (circuit breakers or disconnectors) interconnecting bus-bars and/or bays (feeders). These primary devices are operated in an automated way via a SA system that is responsible for various substation-specific tasks such as controlling, protecting, measuring and monitoring. The SA system comprises secondary or process devices, also known as digital relays, which are interconnected in a SA communication network, and interact with the primary devices via a process interface. The secondary devices are generally assigned to one of three hierarchical levels, which are (a) the station level including an Operator Work Station (OWS) with a Human-Machine Interface (HMI) as well as the gateway to the Network Control Centre (NCC), (b) the bay level with its devices for protection, control and measurement, and (c) the process level comprising, for example, electronic sensors for voltage, current and gas density measurements as well as contact probes or position indicators for sensing switching device states and transformer tap changer positions, and actuators controlling the drive of a switching device or tap changer. At the process level, intelligent actuators may be integrated in the respective primary devices and connected to a bay unit via a serial link or an optical process bus. The bay units are connected to each other and to the devices on the station level via an inter-bay or station bus.
In more detail, a Protection, Control and Measurement (PCM) secondary device, which is also known as an IED in the IEC 61850 standard, controls a particular switching device, and operates on the base of signals from attached sensors for switch position, temperature, voltage, current, etc., signals from other IEDs indicating the state of their controlled elements, and signals from the supervisory system. Conversely, an IED generates signals to act on its switching elements, to communicate its state to other IEDs or to inform the supervisory system. These signals are either hard-wired or transmitted as network messages, for instance according to IEC 61850-8 or IEC 61850-9-2 messages.
In its protection function, a PCM IED monitors the state of a substation or of a part of the substation and autonomously opens an assigned circuit breaker in case the PCM IED detects a potentially dangerous situation such as an overload. In its control function, the PCM IED executes commands from the supervisory level, such as opening and closing assigned switching elements.
In a “select before operate” sequence, an operator may reserve a switching device for operation and command the PCM IED, by way of a switching request, to execute a particular close or open operation on a particular switch. The assigned PCM IED may then accept or refuse such a command depending on the electrical state of the attached lines in order to prevent a hazardous or damaging operation, such as connecting a live bus bar to earth. This safety mechanism is called interlocking.
Conventionally, the logic implementing the interlocking is programmed as Boolean expressions in tabular, code or function chart language on each PCM IED individually during the engineering phase of a substation project, which requires both time and considerable experience as well as a perfect knowledge of the substation topology. Parts of the interlocking logic are “compiled” and comprised in the function chart type logic on the PCM IEDs. This engineering process is normally done on the base of a fixed substation topology, and requires substantial changes in case, for instance, of an extension of an existing substation.
Any custom-made SA system is required to undergo system verification and validation. The supplier of the SA system is expected to demonstrate to a customer the correct coordinated operation of all parts in all possible scenarios, as well as the expected quality or performance such as throughput and timely response also under high load. As the operation of a particular PCM IED also depends on signals that are generated by other PCM IEDs, such signals have to be properly prepared in order to reproduce all expected states of the substation. A large range of tests allowing manipulation of the signals generated by other IEDs have thus been devised. These tests are hereafter called system level tests such as System Integration Tests or System Verification Tests (Factory Acceptance Test (FAT), and a Site Acceptance test (SAT)).
The aforementioned system level tests are generally performed in a test environment or test rig, in which a number of IEDs are installed. However, due to the sheer number of IEDs necessitating an increasingly complicated test rig, and due to cost and space limitations, not all the IEDs of a particular substation are installed for a FAT. Accordingly, the extent and coverage of the test configurations is limited, and in particular, interlocking functionality as detailed above is only partially testable in the factory. The tested IEDs represent only a typical part of the substations and are only given access to a minimum number of signals necessary as input to their respective interlocking logic.
According to U.S. Pat. No. 4,767,941, the implementation of interlocking functionality can be automated provided that the IED knows the actual topology of the substation, i.e. the actual switching states of all switching devices, and an exhaustive set of rules for interlocking operation. Decoupling the topological configuration of the substation from the interlocking rules allows each of them to be updated independently and thus increases flexibility. The signals that indicate the switching state of the associated switching devices are supplied via dedicated data buses and data links to a centralized data acquisition and processing unit. By evaluating the signals, the actual topology of the substation is inferred, and based on the interlocking rules, a release pattern is determined and stored. The latter indicates a release or blocking property for each switching device, i.e. if a specific switching operation request command is to be accepted or refused.